1. Field of the Invention
The present invention relates to a well logging method and apparatus for determining a parameter characteristic of a multi-phase mixture of fluids flowing in a hydrocarbon well during production, e.g. two-phase water-oil mixture or a three-phase water-oil-gas mixture.
2. Description of Prior Art
After evaluating the production capacity of a hydrocarbon well, the well previously cased and cemented is perforated at various depths in order to allow production fluid to rise to the surface. The fluid recovered at the surface may, in fact, comprise a mixture of oil, water, and gas. One of the aims of production logging measurements is to establish not only the nature but also the respective quantitative magnitudes of these phases at each depth.
It is thus important to establish the proportion of the flow attributable to each phase, which proportion is known as the "dynamic" portion or "cut", and comprises the flowrate of each phase divided by the total flowrate. In an oil well, the water and oil phases move at different speeds, with the lighter phase flowing faster than the heavier phase. In addition, the velocity at which one phase slips relative to the other increases with the inclination of the well. The inclination of most wells is more or less pronounced and may, additionally, vary with depth. Thus the cut or dynamic proportion of each phase is different from its volume proportion, referred to as the "static" proportion or "hold-up". The static proportion of one phase is the proportion which is occupied by said phase of a given volume of well as delimited by two transverse cross-sections.
In a two-phase mixture, e.g. of the water-oil type, it is known that the dynamic proportion can be obtained from three parameters, namely: the total flowrate (the instantaneous flowrate of all phases taken together); the static proportion; and a third parameter which is usually the relative slippage velocity of water relative to oil.
Conventionally, the total flowrate is obtained by means of a logging apparatus provided with a flowmeter which may either be of the propeller type (U.S. Pat. No. 3,630,078) or else of the vortex emission type (U.S. Pat. No. 4,442,711). Further, the slippage velocity is usually determined by calculation from values for the static proportion and the relative density, as described for example in U.S. Pat. No. 3,909,603.
The aim of the present invention is to determine the static proportion of one of the phases, and in particular in a flow comprising a mixture of oil and water.
Numerous methods are known for determining the static proportion of each phase. They may be classified into three groups, depending on whether a measurement is performed overall on the entire section of the casing; by sampling a fraction of the flow; or by performing a so-called "local" measurement taken at a point in the flow.
An example of overall measurement is given by measuring the average density of each phase using a differential pressure device or gradient manometer as shown by U.S. Pat. No. 3,455,157. This known device is simple to use, but its accuracy falls off considerably when the flowrate is relatively high i.e. more than about 2000 bbl/d (13 m.sup.3 /h) and with increasing well inclination.
One known way of performing measurements by sampling, makes use, for example, of two plates of a capacitor placed in the flow with variations in capacitance being measured; another method consists in irradiating a deflected portion of the flow with photons. These types of measurements rely on a sample of the flow and it is never certain that the sample is truly representative of the flow.
Local measurements are spot measurements of a physical characteristic of the phase present at the end of a sensor. The characteristic takes only one given value for each phase because of the small size of the sensor relative to the bubbles of one of the phases flowing in the other phase which is referred to as the "continuous" phase. Since the sensor is disposed at a single point in the flow, a measurement of the static proportion at said point is obtained by integrating measurements over a period of time.
The main known methods of performing local measurements are of the electrical type where resistivity is measured (see, for example, U.S. Pat. No. 3,792,347) or of the optical type where a light ray is refracted at the end of an optical fiber (see the article published in "La Houille Blanche" number 5/1978, pages 351-355), or of the radiofrequency type in which the dielectric constant is measured (see German Pat. No. 2,558,588).
Theoretically, the average value of the static proportion of each phase on the borehole cross-section can be obtained from local measurements by performing measurements at multiple measuring points, an by integrating the local measured values over the entire cross-section of the well. To this end, either a plurality of sensors are used to enable the measurements to be performed simultaneously, with the consequent risk of the flow being disturbed and with various construction difficulties, or else a sensor (or a few sensors) is displaced to each measurement point, thereby giving rise to an unfortunate loss of time.
The present invention makes it possible at each depth to obtain the value of the average static proportion of each phase over the entire well cross-section corresponding to a given depth, with said values being accurate and obtained with considerable saving of time.